Thank you for joining us for Antero's Second Quarter 2019 Investor Conference Call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up for Q&A.

I'd also like to direct you to the homepage of our website at www.anteroresources.com, where we have provided a separate earnings call presentation that will be reviewed during today's call.

Before we start our comments, I'd like to first remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero and are subject to a number of risks and uncertainties, many of which are beyond Antero's control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

Today's call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure.

Joining me on the call today are Paul Rady, Chairman and CEO; and Glen Warren, President and CFO.

Thanks, Mike. Thank you to everyone for listening to the call today. In my comments, I'm going to spend some time talking about our long-term strategy and focus on our recently announced well costs and operating cost-savings initiatives. I'll provide detail on savings we've achieved to date and highlight the key items that will reduce cost further towards our target. Glen will then highlight our second quarter financial achievements, including the premium NGL price realizations following our first full quarter with Mariner East 2 in-service. He will conclude by discussing our expanded hedge position through 2022 and our capital spending outlook.

I'd like to start by discussing our long-term strategy. We remain focused on maximizing our ability to generate free cash flow on a sustained basis. As we look at our 5-year development plan today, the best way to deliver maximum free cash flow on a sustainable basis is to grow production in the near term to fill our firm transportation commitments, while we have attractive natural gas prices -- natural gas hedges in place.

At current commodity strip prices, we forecast funding this growth primarily through cash flow from operations and the water earn-out payments of $125 million expected in Cal-20. This allows us to preserve our strong balance sheet.

Once we grow into our firm transport and essentially eliminate net marketing expense in 2022, we are well positioned to be more flexible with our development plan and generate significant free cash flow. To provide some context, if we elect to just maintain year-end 2021 forecast production of approximately 4 Bcf equivalent per day, the capital required to do so would be less than $900 million. This would result in our ability to generate free cash flow of over $400 million in Cal-22 even at today's commodity strip prices or over a 30% free cash flow yield.

Now let's turn to our well cost-savings initiatives. Regardless of commodity price cycles, we remain committed to maximizing value. Over the last several quarters, we undertook an internal review of every expense associated with our well costs with the goal of materially reducing cost to maximize returns.

Let's turn to Slide #3 titled Targeted Marcellus Well Cost Reductions. Please note that all these numbers assume a lateral length of 12,000 feet. We are targeting a reduction in well cost of 10% to 14% on a per lateral foot basis or approximately $1.2 million to $1.7 million per well by 2020 compared to our 2019 budgeted cost. On a dollar per foot basis, this translates into a reduction from 2019 budgeted costs of $0.97 million per thousand feet to a target of $0.83 million to $0.87 million per thousand feet. This is expected to be reached by the beginning of Cal-20.

These savings have come or will come from a combination of water-savings initiatives, service cost deflation and continued efficiency gains. Meeting our target will position us at the low end of the cost curve among our Appalachian peer group.

Now let's take a step back and talk about what we've already achieved to date. Following the waterfall on the page, we begin with our January '19 well cost at $0.97 million per thousand feet that was assumed in our budget. During the first half of the year, we've already achieved savings of approximately $500,000 per well, which brings us to our current AFE with second half 2019 well costs estimated at $0.93 million per thousand feet. This progress was the driver behind lowering our 2019 CapEx guidance back in May without any change to our planned activity.

We're very proud of our team's ability to deliver on this target significantly ahead of schedule. This achievement reflects both continued operational efficiency gains and service cost deflation that was realized during the first half of 2019. From our current AFE of $0.93 million per thousand feet lateral, we expect well cost to decline further to the range of $0.83 million to $0.87 million per thousand feet by Cal-20. These additional savings are expected to come primarily from our water-savings initiatives, both on enhanced flowback water management and completion optimization.

Now let's take a closer look at our major components of our well-cost savings. We talked about the timing of well-cost savings, but I wanted to provide a breakdown of the magnitude of each category.

On Slide #4 titled Cost Reduction Initiatives Breakdown, you can see the breakdown by category, assuming the midpoint of our targeted well cost reductions of $1.2 million to $1.7 million. We are targeting approximately $800,000 per well in well cost reductions for more efficient flowback and produced water management as well as optimized completion design.

On the flowback and produced water side, we expect to reduce cost through the combination of; first, polishing and blending the water to reuse in completions; secondly, repurposing portions of our existing freshwater system to transport the water; and three, constructing additional water pipeline infrastructure. Historically, we've used third-party trucking companies to transport our flowback and produced water at a cost of between $6 and $9 per barrel. Over the last 12 months, we have paid nearly $160 million to third-party trucking companies.

This situation provides Antero with a significant opportunity for improvement and for material savings on a per barrel basis, while also expanding the scope of the flowback and produced water services business for Antero Midstream.

On the water used for completions, earlier this year, we began performing pilots across our acreage to test and analyze the optimal completion design to maximize returns. After successful pilots using mostly 100-mesh proppant, we now plan to reduce water used in completions from a range of 40 to 45 barrels per foot down to 35 to 38 barrels per foot in a new cost-efficient completion design. The completion design optimizes both fracture length, driven by water usage and reservoir conductivity which is driven by the type and amount of proppant in the most cost-effective manner. We've not seen any evidence of degradation in either production or EURs in all of our piloting and we do not expect it going forward.

The second component of our well cost-savings initiative is service cost deflation and efficiency gains. An often overlooked byproduct of lower commodity prices and reduced industry activity is a deflationary service cost environment. Service cost go down. This is especially true in the Appalachian Basin where producers have lowered capital programs, while also continuing to realize efficiency improvements.

Given that Antero has remained one of the more resilient producers in the basin through all cycles, we've maintained excellent relationships with our vendors. In early 2019, we began working with our vendor partners to find areas to reduce expenses. The result of these extensive conversations was a meaningful reduction in total vendor cost. Further savings will come from last-mile sand-sourcing logistics and an additional sand contract that was recently finalized with a premier sand supplier.

On the efficiency gains, as we have highlighted during many of our earnings calls, our team's operational efficiency gains continue to surpass expectations. Slide #5, titled Marcellus Drilling and Completion Efficiencies, highlights the many advancements that we achieved during the second quarter of 2019. During the quarter, we averaged 5,470 feet of lateral drilled per day. It's approximately 1 mile, a little over a mile every single day, 20% improvement from our 2018 average.

In addition, we achieved what we believe is a world record, again, by drilling a total of 9,650 feet of lateral in 1 day, which we're extremely proud of. Completion stages per day averaged 5.7 stages per day, an increase from the 5.2 stages per day average in 2018. We continue to drill longer laterals. During the quarter, we were able to drill our longest Marcellus lateral ever at 16,279 feet sideways. These efficiency gains, combined with service cost deflation, are expected to reduce well cost by approximately $650,000 per well, assuming the midpoint of the target range.

The enhanced produced water management will also reduce lease operating expenses. Let me clarify how we talk about water in terms of well cost and LOE. When we complete a well, after perforating and stimulating it, we flow the well back and begin to recover the water as we turn it in line. We categorize the first 90 days as flowback water and the cost to truck and recycle it is capitalized as part of the well cost. After 90 days, we account for the well -- the water as produced water, and the cost to truck and recycle it is considered LOE.

So let me talk a little bit more about LOE, lease operating expenses. In the first half of 2019, produced water cost represented approximately 80% of total LOE. Assuming Antero Midstream provides the new expanded produced water services, we expect LOE to be reduced by at least 20% in Cal-20 compared to Cal-19 budgeted cost. This equates to savings of at least $50 million on an annualized basis.

Slide #6, titled Appalachian Peer Marcellus Well Cost Comparison, provides a snapshot of our Appalachian peer well costs and future targets. Keep in mind that there is a variance among producers as to what costs are captured in capitalized well costs versus LOE, but the trends are useful. As you can see, our new well cost target will move us from an average ranking to becoming one of the lowest-cost producers in the lowest cost natural gas basin in the world. While we recognize that some of these cost initiatives have not been fully realized to date, we are already seeing results from the company's focus on costs as we achieve the lowest capital spending quarter in our history at $303 million for the quarter.

Over the last 12 months, our drilling and completion CapEx was $1.55 billion, which delivered 700 million cubic feet equivalent of production growth. This was accomplished while spending near-cash flow levels, highlighting the attractive capital efficiency of our asset base. Going forward, we anticipate a quarterly D&C CapEx run rate approximately in line with the second quarter spend in the $300 million to $325 million range.

In summary, we will continue to prioritize maximizing value through an intense focus on costs. The reduction in well cost is expected to deliver 2019 drilling and completion capital at the low end of our guidance range and lead to a lower D&C capital target of $1.2 billion to $1.3 billion in Cal-20. The decline in capital spend during Cal-20 is despite a similar number of the well completions to 2019, but actually with a 19% increase in total lateral footage completed next year due to longer laterals.

Thank you, Paul. The second quarter was the first full reporting period with the Mariner East 2 pipeline in-service, giving us access to premium priced global LPG prices or markets. We hold about 1/3 of the current 165,000 barrel a day of capacity on Mariner East 2, making us the largest shipper on this pipeline.

During the quarter, we realized an unhedged average C3+ NGL price of $28.57 per barrel for the quarter, that's a $1.68 per barrel premium to Mont Belvieu pricing, as shown on Slide #7, titled Inflection Point in NGL Marketing and Pricing. 55% of C3+ volumes were exported and realized at $0.19 per gallon premium to Mont Belvieu pricing. In the table on the right-hand side of the slide, we provide guidance on NGL realizations relative to Mont Belvieu pricing for the full year 2019. As you can see on the blended basis, it's essentially flat to Bellevue to a slightly positive premium of $0.4 per gallon.

Now let's take a look at the impact of that ME2 has had on Northeast NGL differentials. Since the in-service of ME2 in February of this year, Antero's NGL price differentials improved by over $6 per barrel, flipping from a discount to a premium to Mont Belvieu. This improvement is not only from our sales in the international market but also from the strengthening of in-basin pricing in Northeast. The approximately 165,000 barrels a day flowing on ME2 evacuates almost 40% of the basin's NGL supply.

On Slide #8 titled Improvement in Northeast NGL Differentials, you can see the significant improvements in price realizations following the start-up of ME2. ME2 is that dotted vertical line over to the right. First half 2018 realizations average and approximate $5.75 per barrel discount to Mont Belvieu. Despite the softer domestic prices seen during the first half of 2019 versus the prior year, our realized price relative to Mont Belvieu improved by over $6 per barrel and flipped to a premium to the index.

In addition, and also not depicted on this chart, our in-basin C3+ NGL price realizations have also improved following the start-up of ME2. C2+ NGL realizations over the past 4 years have averaged about $7 per barrel, you can see that on the orange line there, discount to Belvieu but it improved by 30% in the first half of 2019.

Looking forward to 2020, with the completion of the full ME2 project expected by the end of 2019, total pipeline capacity will increase to 275,000 barrels a day on ME2. At that time, we have the option to increase our capacity by as much as 50,000 barrels a day and 10,000 barrels a day increments that would take us up to 100,000 barrels a day of firm capacity, which would increase our exposure to international pricing to the 65% to 75% range on Antero's expected NGL production in the year 2020.

This expansion would also evacuate a higher percentage of regional supply, which is expected to further boost in-basin price differentials. Our significant volumes on ME2 give us the highest exposure to international LPG markets, which positions us to deliver peer-leading NGL price realizations going forward.

For those of you who have missed it, we have been publishing a new presentation on our website titled Weekly International LPG Pricing Update on the homepage, which provides a summary of benchmark international commodity prices for propane and butane. We hope this helps provide better visibility on the 50% of our NGL volumes that we sell into international markets. In short, the propane and butane futures curve is in contango over the next couple of years and the Northwest Europe prices are the $0.08 and $0.14 per gallon premium, respectively to Mont Belvieu net of shipping.

I'd like to touch on the NGL macro briefly. The current weak NGL pricing in Mont Belvieu is due to limited export capacity along the Gulf Coast. Although we expect soft prices to persist through the third quarter, we do see Mont Belvieu fundamental strengthening during the fourth quarter and into 2020. The completion of export expansion projects along the Gulf Coast are expected to come online by the fourth quarter of this year, providing relief to the stranded supply that is negatively impacted Mont Belvieu NGL pricing.

In the Northeast, the in-service of full capacity on Mariner East 2 will provide increased exports through the Marcus Hook terminal. We expect these projects to provide upside to domestic prices as well. We also see strengthening of international prices as up to the 6 new PDH plants are expected to be placed in service in China by year-end this year, while Europe and India are also expected to complete additional import terminals. In summary, we expect NGL pricing to improve as we see fundamental strengthening in the coming quarters.

Turning to Slide #9 titled Pure Leading Hedge Protection. During the second quarter, we added to our 2020 and our 2021 natural gas edge positions. We are now approximately 90% hedged in 2020 at an average price of $2.87 per MMBtu and over 35% hedged in 2021 at an average price of $2.88 per MMBtu, assuming approximate 10% annual production growth each year.

It's important to note that we continue to offset our annual net marketing expense with the hedge realizations. Based on strip pricing today, our hedge realizations will more than offset our net marketing expense through 2021, as you can see depicted on Slide #10. It's notable that we remain the only publicly traded U.S. producer that is 100% hedged on expected natural gas production in 2019, as shown on Slide #11 and 12, and have significantly more hedge protection in 2020 and 2021 than most of our Appalachian peers. This is an important investment attribute in a bear market for gas.

Moving on to Slide #13 titled Strong Financial Position for Low Price Environment, our balance sheet is in the strongest position in our company's history. We have reduced absolute debt by over $700 million over the last few years, resulting in low 2x leverage. We have $1.4 billion of value in our AM ownership that provides us over $200 million per year of steady cash flow. Our borrowing base was reaffirmed at $4.5 billion during the spring redetermination that was in April with unchanged commitments at $2.5 billion and only $175 million drawn on the facility. We have over $1.6 billion of liquidity available. This highlights the strength of our asset base and the depth and resilience of our drilling inventory.

Before turning the call over to questions, I would like to comment further on our well cost reductions and capital outlook as we look ahead. As Paul mentioned, the $303 million of CapEx was a quarterly low for us. However, the new well cost savings initiative underway, we expect to deliver quarterly CapEx in the low $300 million to $325 million rage through 2020, assuming the current commodity strip. On an annualized basis, this results in CapEx in the range of $1.2 billion to $1.3 billion in 2020.

The reduced well cost, combined with our strong hedge position over the next several years, support measured production growth, while spending near-cash flow levels. As a reminder, in 2020, we anticipate receiving the $125 million water earn-out payment from Antero Midstream and approximately $150 million for the natural gas pricing litigation, providing further support to our balance sheet.

Our focus remains on maintaining a strong balance sheet. We have the flexibility and the strong asset base to adjust our development plan, depending on the commodity price environment. Lower well costs led to a reduction in our maintenance CapEx estimates.

Turning to Slide #14 titled Maintenance and Decline Rate Projections, we now project maintenance CapEx, that's to keep production flat at 3.2 Bcfe a day, to be approximately $670 million.

In summary, please turn to Slide #15 titled AR has Built a Resilient Business Model. Despite the macro and market headwinds today, we've built a business that is resilient through all environments. We've achieved significant scale and product diversity, while maintaining balance sheet strength. Our peer-leading hedge book and midstream ownership provide substantial liquidity and affords us protection through sustained downturns. These attributes differentiate us versus our peer group and provide flexibility to succeed under varying market conditions. We are very well positioned as a company to generate significant sustainable free cash flow over the long term.

There's certainly a chance. That's something we monitor, and we do have number of Utica locations that are at the very low end of our cost curve. But at the end of the day, you're much better off completing pads in the same general area from an operating and a capital cost standpoint. So right now, we’re really massed to develop in the very much liquids-rich Marcellus. But we like the Utica as well, and we just brought on 6 dry gas wells, which you are probably alluding to in the quarter, and those look really strong.

I don't believe it's NGL recovery-driven. I think you're just going to see a little variance quarter-to-quarter on that as we jump from completions in the 1,240 Btu to the 1,275 Btu and back and forth, so that's just going to vary. And those are pretty chunky obviously when bring it on 8-, 10-, 12-well pads so it can impact the quarterly numbers a bit.

Okay. Okay. Perfect. And then just one last one from me. The previous multiyear guidance, I think it had something of a 10% to 15% sort of soft guide for growth but obviously at a much higher commodity price. Should we think -- how should we be thinking of that going forward? Obviously, prices are lower but you've done a lot to offset that vis-a-vis costs. How should we frame that moving forward?

Yes. I think you can see from all materials in the press release we're very much focused on that sort of 10% CAGR over the next several years for production growth, so we're not looking at that upside growth case. In fact, if we see improvement in commodity prices, which we certainly think that we will over the coming quarters and years, that'll just to be captured as additional cash flow for deleveraging and other uses, not for accelerating the capital plan.

Yes. Well, I mean, you can see we're right at our guidance for the year on production. So I think you'll see that pretty flat through the year, and then we expect capital as we stated in the call. We expect that still run in that $300 million, maybe a little bit over $300 million each quarter for the next many quarters really.

Okay. Okay. And then given very strong 2Q production, I'm just curious if that was expected, given the well cadence on your side -- given very strong 2Q production, how should we think about full year production guidance? Are you expecting now to come in on the high end of the full year production guidance, midrange or maybe low end?

I think the midrange is a good expectation. It does -- the quarterly numbers depend a bit on the cadence, and we've been fortunate to bring pads on earlier than expected, and we've also really liked the results, so we've seen the productivity of the wells. So I think you're seeing some of that. But no, we're not raising to the high end, I think the midpoint is a good place to be.

Okay. Big number. And then admittedly my understanding of the entire water value chain could be better. So with that in mind, can you sort of help us -- I mean, I remember it wasn't that long ago that we we're talking about using more water per foot in our completions. So I guess, what has changed, and then maybe give us a sense for the pilots that you've done so far?

Yes. Well, what has changed as we said in the remarks, really the interaction between wells that you go on wider fracs the more -- or the fracs go further out away from the wellbore, depending on how much water you use. The converse is with sand, it's better near bore conductivity, as we say, the fractures are well connected. So we saw that we didn't need to go quite as wide and half-length between wellbores that we could cut back on the water. What we see, of course, the industry, and so we are seeing things that just the way the industry is that 100-mesh is a little bit simpler. We use some of the coarser meshes in some of our designs. But we can get the jobs off pretty quickly with virtually no screen-outs by going with the 100-mesh, and when we do that, it requires less water. So we are able to cut back just a little bit, so 10% or 15% cut on the water and stick with mostly 100-mesh on the proppant, and that's working well.

$280,000 per well just on the water and then the actual produced water savings because you have lower produced water because you now put less water in it, so further $108,000. So it's about $400,000 in total.

Right. So the first $200,000, remember, we were explaining that we call -- the first 90 days of the water coming back, we call that flowback and so those cost to truck and cleanup are part of the well costs. So that's the $280,000. And then the next amount that Mike talked about is the LOE savings beyond the first 90 days, but it's material for both. It's definitely an important cash factor for us.

Yes. That's very helpful. Maybe this is one for you, Glen. I know you talked in detail on the release about utilizing the lower cost FT as opposed to the higher-cost project. So can you just give us some maybe some color around that? I don't know if you want to reference projects, but just kind of help us understand those comments.

Yes. At the end of day, I think our molecules are just chasing the best pricing, the best netbacks and when you have tight differentials in the basin, and you're keeping some of the gas closer to home, and that's what we've seen some in the second quarter. I think it's as simple as that.

Okay. Okay. That's helpful. And then maybe finally, from me, just on high level, just kind of thoughts around the AM ownership here. I know historically, you sort of used that to raise capital at least each year, maybe with the exception of 2018, but there was a lot going on with the simplification in that year. So maybe just high-level thoughts on the AM ownership?

We like the ownership. You can see the $200 million or so of dividend stream and simply growing over time. So it'd be tough to sell it, particularly today at a 13% kind of yield. So tough for us to let go that is what I'm getting at. So we're not inclined to do anything with it today, and we really enjoy that ownership and see tremendous amount of upside in AM. So I think we'll stand pat for now.

Yes. Of course, we've got great rates on those 2 bonds that you're alluding to, and they come due at the end of each of those years. So we've got almost 2.5 years on the 2021 maturity, and obviously more like 3.5 years on the other one. So not real sense of urgency there. We pick our spots with the bond market, and it's kind of tough around the last month or so. And so we'll be opportunistic about that. But I think that's not something that keeps us up at night by any means. We've got tremendous amount of liquidity on our credit facility, very strong bank group, more banks wanting to get in to our credit facility, so that's all. All in good shape as far as we're concerned.

Great. And then just a couple of follow-ups on the points made earlier. The $1.2 billion to $1.3 billion exploration and development budget, what production growth do you expect that to get you in 2020? And then with regards to the $150 million of litigation proceeds, what are the risks, if there's any, to the upside or downside with regards to receiving those proceeds or the time line to receive them?

Yes, on the production, I mean, we talk about a 10% production CAGR, and that's a multiyear look. So I think you can handicap that, give or take, 2% or 3% either side of that, but that's kind of the outlook for the next few years. So I think you'll see us sort of average 10% production growth. And that $1.2 billion to $1.3 billion next year keeps us very much on that track. And then similar levels, we really don't need much of an increase over time, over the next few years, to deliver that over that $1.2 billion to $1.3 billion range, it stays in that range. So we feel good about that.

On the litigation front, yes, those -- we wouldn't talk about those publicly if they weren't pretty far down the road. And so there was a jury trial on the biggest piece of that with a utility with the WGL, and that ended very much in our favor. And they can always -- the other side can always appeal, of course. So that -- the timing would be the risk, I would say, on that, could come sooner, could come later, but I think that's a good handicap ending the year 2020. The other one is South Jersey, Brian, you can read about that in the Q or 10-K, that's pretty well described there, but similar kind of circumstance.

My water vocabulary is also challenged. So just wanted to ask for some clarification. My understanding at least is that there's a few pathways in the water business. One is the disposal, cleaning it up through Clearwater and putting it into, I guess, nearby water bodies, et cetera. The other is recycling and there might be other aspects of it. But could you kind of clarify where these savings are occurring, first of all? And second of all, what remaining aspects of the water handling are future challenges? And then finally, is the water stuff discussed on the print today, is it 100% application? Or are you easing into it in 2020?

No, I think that's a good tutorial on what's going on. So I mean, I'll turn it to Paul. But the first way to think about it and I think is really what we're doing is kind of shortening the loop as we move north in the liquids-rich area. I mean some of that is 25, 30 miles away from some of that development from Clearwater. So you might think of it as rather than taking it all back to Clearwater where the trucking can be $6, $7, $8 a barrel, we're essentially reusing it right there in the area. So that's how we refer to it as local reuse and it goes right back into the next completion. So just shortening the loop and taking the trucking out, and the fees are also presumed to be a bit lower for the cleanup of the water we're doing locally.

Yes. That's right. The fees can be lower because the cleanup, we can take advantage of a blending as well by just taking the affluent, just as Clearwater does. But not doing as deep a cut on the flowback and produced water, and blending it down and using it in the future completions. So as Glen said, big savings on the trucking side because we're keeping it close to where the development is, and then big savings on the cleanup in that we can use polishing and blending down to be a little more economic.

And then in terms of what we've been talking about, we've been completing wells in the liquids-rich fairway with, call it, 75, 25 freshwater and then the cleaned up water, I think, locally. And that will vary over time, it can be 80-20, it's just going to vary a bit. We are blending in some water that's treated locally is the whole concept, and we'll be doing some of that this year and I think Subhasish asked about proportionally.

Yes. We're stepping into it as we speak. We have a number of pads that we are completing here in the third and fourth quarters of Cal-19, and those are up in this focused development area to the north. And so we'll be doing both polishing and blending there and step into it in a more fulsome way through Cal-20.

Yes. We've -- and our logistics team working to do -- work hard on the logistics. We're fortunate that our acreage position is quite concentrated, so we don't have the issue of pads distant from each other. And so in that way, it's not only efficient for midstream for the hookups but for water transfer between pads. As we flowback one pad, we can use that water right next door to complete the next pad. So a nice focus that way. And -- so the goal will be to do it on all 110 to 120 wells next year and apply those savings, not only the well cost savings, but the LOE savings throughout the board.

Got it. Okay. I'll let that sink in. I'll probably follow-up off-line in the next couple of weeks. Just another follow-up on the simultaneous operations, is that -- on the larger pads, is that pretty common right now? Is that built into the 2020 guidance?

It's -- we've done it, we've done it recently, the sign-ups, where we're having either 2 crews at once on different ends of the pad. We're completing or we're drilling on one end and completing on the other. But I think we have enough flexibility that we don't have to do that all that often and there's not much gap in cycle times. So we're built to do that, but we -- it's probably about 15% of our pads that we do sign ops on.

Glen, maybe for you just on leverage, picked up a little bit in the quarter. When you think about trying to maintain what has been typically a pretty conservative balance sheet, it sounds like in the near term you're kind of comfortable with the level liquidity and funding the outspend that way. But when you think about different levers you may have to address and keep leverage in check near term, I guess, how are you guys thinking about some of the noncore stuff you may have, whether it's Utica or have you, AM units or slowing down?

The slowdown, that's not really in the cards. I mean, that's what this is all about, right, improving capital efficiencies and reducing well costs, it enables us to continue on the pace that we've been talking about, so that's really not something that's being kicked around. And in terms of cash flow, free cash flow needs, the outspend, it's in the -- over the next 3, 4 years, it's in the several hundred million dollars, it's not using stage throughout and that's probably due our hedge profile and all that. So it's not a real big number. So the actual debt itself, we don't see that increasing much. It's just that EBITDA has come down a bit for everyone over the past few quarters with the commodity price coming down. So it's really the denominator that's come down a bit. So we're managing the balance sheet just fine, it's not growing tremendously, and we're very comfortable where we are and you'll see us continue to hedge opportunistically as well.

As far as -- I'm sorry, you mentioned divestitures or whatever. The door is always open for that. We consider that, we look at those from time to time. But I'd say, there's not a big initiative to go out and sell a chunk of our position. We like all of our position, and it gives us sort of unparalleled inventory in the basin. But yes, the doors are open for those kinds of things. So I don't think they're big needle movers but it could happen.

Understood. That's helpful. And then just on ethane, can you remind us what your FT minimums are there? And is it, I guess, fair to assume that just the current price in the strip, you project above those levels?

Yes, we're recovering 40,000, 41,000 barrels a day and much of that is for firm sales. Our FT, we have 20,000 barrels a day on ATEX for ethane transport to Mont Belvieu. We've laid some of that off, so net to Antero, 10,000 barrels a day which we are using to facilitate firm sales here and there. But we have a number of firm sales to different parties, both internationally and also domestically, internationally including Sarnia. So we're a little above -- our firm sales are a little bit higher than our must recover, but we always have an eye on Btu of the residue stream coming out of the plants. And we certainly have flexibility to recover more. But right now, as you know, the numbers say reject the ethane where you can, except, again, to stay within spec and also to fulfill some firm sales on ethane.

I would say about, yes, 10 to 20 years, I would say. We're a base provider for the upcoming Shell Cracker just west of Pittsburgh. So that will be even more supply and that is 20-year contract there and some of our...

Your preliminary 2020 comments on free cash flow suggest $275 million outspend, excluding onetime items. Can you help provide color on any drivers that may be impacting the outspend other than transport fee assumptions?

Yes. I think as we outlined earlier in the call, I don't know if you missed that, but we want to fill our transport. And we still have economic drilling to do, and so we're staying the course rather than simply hit the brakes to generate free cash flow next year. We still have a lot of firm transport to fill next year.

Okay. And then moving on to my last question. I'm just wondering if you can provide free cash flow sensitivity to, say, $1 change in C3+ NGL pricing, given your mentioned the $29 assumption a bit helps your pricing for next year?

Gentlemen, last December you unloaded some of the 2019 gas hedges, it looks like a rare miss on your hedging strategy. Are you bullish on gas in 2020 on decline rates? And was your timing just off? Or did the new longer-dated hedges that you put on in the second quarter suggest a more pessimistic view on go-forward pricing?

Well, to be in this business, one has to be optimistic. So we are positive thinkers and optimistic, but we're also defensive. So the hedges that we added were definitely -- it's not only a price target but it's when does it happen. And so just to be protective of the balance sheet, we added hedges through Cal-20. You're right, as we monetize some hedges, always have an eye on delevering and putting forward the best credit metrics. We were seeing a positive set-up in terms of supply and demand when we did that back in December. But, yes, a hindsight that was a miss. We would've been better off to just hold onto those. We wouldn't have paid down the $350 million of debt or so. But we would've -- we marked that to market every month or so just to learn from our decisions and that was one where it would have been maybe $100 million ahead by not doing that.

Yes, I think it's really -- demand has been soft -- a little bit softer than expected, it's not really been the supply. And then just the overall sentiment, so that kind of caught us offsides, I guess, Ethan.

Okay. And then in terms of the strategy, you guys have laid out some nice seemingly kind of incremental improvements to the business, but that doesn't seem consistent with the kind of urgency I'm hearing from clients about the decline in the stock prices. You addressed potentially laying off FT, are there any other strategic moves available to you, like selling acreage, potential midstream asset, JV sales that might help arrest some capital declines and preserve capital here?

Well, there's all of that. But I mean, keep in mind, we're 2.3x levered and we have well over $1 billion of liquidity. So I mean there's not a real sense of urgency to do those kinds of more dramatic things. And sure, we're always looking at strategic things, a lot of which we can't really talk about publicly until they're done, but we're always working on lots of different alternatives.